Focus on Dutch Oil & Gas 2014
Foreword
Natural gas production is important to the Dutch econo- my. Not only because of the state revenues (about EUR 15 billion in 2013), but also because of the employment that the gas industry offers in the Netherlands (16,000 direct and indirect jobs).
The role of the ‘small fields’ in Dutch gas production will become more important, especially now that production from the Groningen field has been further capped. In
‘Focus on Dutch Oil and Gas’ we present our annual overview of the state of play of the Dutch small gas and oil fields and of major new developments. The main con- clusion this year is that a sharp increase in investment is necessary to maintain production from small fields over the next one-and-a-half decade. In that perspective we have to focus on exploration (fallow acreage, open areas, new plays), continuation of the maximisation of economic recovery, the upside scenario and stakeholder engagement. The opportunities are there, but an incre- ased and cooperative effort is required.
Last year the about 300 small gas fields in which EBN participates produced 26 BCM (billion cubic meters) of natural gas – one-third of total Dutch production (the remaining was production out of the Groningen field and non EBN small fields). Relatively spoken the small fields become more and more important, but we need an extensive exploration, appraisal and production optimisa- tion investment program.
Such investments are urgently required as the long-term production outlook from existing fields continues to level off. Indeed, more needs to be done. This report shows that the growth of production based on the optimisation
decline in production, more investment must be directed at exploring new resources as well as unlocking more challenging resources, such as tight and shale gas plays.
This is not impossible. The good news from this report is that profit margins of small fields production remain attractive. This is partly because gas prices remain robust. Tax incentives for specific marginal developments have also been helpful, although these incentives do need continuous fine-tuning to remain effective.
Although the opportunities are there, the public image of natural gas has worsened considerably in recent years.
The industry will have to share its knowledge more exten- sively with their partners and stakeholders, and enter into the discussion about the benefits and the necessity of gas extraction in the Netherlands. More than ever, it will be necessary to create social support in order to secure the future of the Netherlands as a gas producing country.
This report shows that the Netherlands can remain self-sufficient in gas production for at least a decade and still produce a significant part of its consumption a few decades from now, however, to achieve this goal will be increasingly challenging.
Maximizing economic recovery by means of safe and sustainable domestic production is essential for the Dutch E&P industry as well as the Dutch society, there- fore a new commonly shared commitment to small fields exploration and production is necessary.
Berend Scheffers
Executive summary
This year’s Focus on Dutch Oil and Gas reviews the status of the Dutch E&P industry. The Dutch onshore and offshore reserves and resources are still large, but declining. Increased effort and further optimisation are required to minimise the decline in production, in the form of higher investments in exploration and wider applica- tions of new technology. Such optimisation will enable the Netherlands to benefit from the proceeds of Dutch natural gas and oil for many years to come.
Thanks to an increase in activities in recent years, the production decline from the Dutch small fields stabilised at 2.5% over the past two years, while the small-fields reserves base decreased by only 6.3 BCM. Despite these relatively positive signs, the long-term outlook does show a decline in production from 2019 onwards.
The most recent ‘business-as-usual’ scenario shows a project portfolio that is still substantial enough to maintain a plateau production of 28 BCM for the next five years.
However, the decline in production will continue unless investments are made to unlock resources identified by onshore and offshore exploration, but also in more chal- lenging tight and shale plays.
Despite active exploration, the Dutch small-fields onshore and offshore reserves and resources base is declining.
The average reserves replacement ratio for on- and offshore fields is well below 100%. Since offshore reserves comprise 63% of the total reserves, maturation of offshore contingent and prospective resources into reserves is required to maintain the offshore fields’ sizea- ble contribution to production and reserves. This requires substantial additional investments in exploration and production activities. EBN will continue to encourage and
assist operators to maximise their exploration potential and increase investment levels.
The Dutch E&P sector offers attractive relatively low-ca- pital and low-risk investment opportunities. However, on average only one third of the cash flow generated from E&P activities in the Netherlands is reinvested in new Dutch E&P activities, while the remainder is invested else- where in the world or paid out as dividend. The worldwi- de reinvestment ratio for major E&P operating companies in the past two years was approximately two to three times higher. Consequently, there certainly seems scope for a higher investment level in the Netherlands.
The Netherlands offers a stable and supportive E&P investment climate. In 2010 the Dutch government successfully introduced the ‘Marginal Fields Tax Allowan- ce’ (MFTA) to improve the attractiveness of investments in developing marginal offshore gas fields. The Wood Review, commissioned by the UK government, describes the Dutch E&P investment climate and stable govern- ment regulations as exemplary. However, this does not mean that there is room for complacency.
In the ‘business-as-usual’ scenario, a further 45 BCM can still be produced from prospective resources in 2050.
This estimate is based on currently identified projects and excludes prospects yet to be defined. However, timing is crucial, especially offshore. The risk of offshore infrastruc- ture disappearing in the near future is driving the urgency for exploration. Encouraging timely exploration activities is consequently one of EBN’s key missions. Increased throughput of installations and cost-effective tail-end production are becoming progressively important in order to defer abandonment. A side effect of extending produc-
tion, is the fact that this will also allow deferring the costs of abandonment, currently estimated at around €5 billion.
The Netherlands is a net exporter of natural gas and, based on the current levels of domestic gas consumpti- on, will be able to remain self-sufficient for at least ano- ther decade to 2025. If the upside scenario materialises, this might be stretched to 2030. In addition to self-suffi- ciency, the proceeds from natural gas strongly contribute to Dutch State revenues. Domestic production contribu- tes to a sustainable energy supply because imported gas supplies, such as LNG shipped from Algeria and pipeline gas from Russia, cause considerably higher greenhouse emissions than domestic production.
A total of 85% of the existing gas fields in the Netherlands are producible by conventional technology. Although the remaining Dutch small-fields portfolio is categorised as tight, these fields can also contribute to a sustainable energy supply, particularly if the recovery factor can be increased. A key technology for improving the recovery factor of tight fields is hydraulic stimulation.
This technology has been successfully applied in the Netherlands and elsewhere in the world for over fifty years, with recovery factors increasing every year. EBN anticipates that if multi-stage hydraulic stimulation is systematically applied in the Netherlands on a larger scale, the average recovery factor of tight fields could increase from 47% to 60%. The production success of hydraulic stimulation increases with increasing volumes of pumped liquids and a higher average concentration of pumped proppant. The success rate also increases with the proppant’s grain size.
With many gas fields approaching their end of field life, the Netherlands is generally seen as a mature, but attrac- tive gas province. However, some geographical areas or geological plays are still underexplored. EBN is currently focusing on studies aiming at increasing exploration activities and investments by existing operators, and attracting new players.
Contents
Foreword 003
Executive summary 004
1 Reserves and investment opportunities 008
1.1 | Reserves and resources reporting – PRMS 008
1.2 | General overview of historical production in the Netherlands 008
1.3 | Reserve and resource database 010
1.4 | Gas production forecast 011
1.5 | Benefits of Dutch natural gas 013
1.6 | Profit margins on production from small fields remain attractive 016
1.7 | Marginal fields and prospects incentive 016
1.8 | Historical and required investment levels 018
1.9 | Comparison of reinvestment levels: Netherlands versus the rest of the world 020
2 Activities and innovations in the Dutch E&P industry 022
2.1 | Increasing drilling activity in the Netherlands 022
2.2 | Historical E&P activity levels in the Netherlands 022
2.3 | Innovative solutions to increase oil and gas recovery in the Netherlands – TKI innovation projects 024 2.4 | Hydraulic stimulation is key to achieving economic production from poor-quality reservoirs 026
3 Developments and innovations of offshore infrastructure 032 3.1 | Offshore infrastructure, a brief history and innovation over time 032
3.2 | Innovations in offshore E&P 034
3.3 | Tail-end production and optimisation 035
3.4 | Reduction of operating costs – paradigm shift required 036
3.5 | Tail-end production challenges: water production 037
3.6 | Abandonment expenditure and development over time 038
4 Exploration activity 040
4.1 | Measures to increase exploration activity in the Netherlands 040
4.2 | Oil activity 042
4.3 | Exploration study in the Northern Offshore: D, E, F, A and B blocks 042
4.3.1 | Underexplored Chalk 042
4.3.2 | New source rock in the Northern Offshore? 045
4.3.3 | Potential of Zechstein carbonates in the Northern Offshore 046
4.4 | Accuracy in prospect risk prediction 046
Glossary 050
About EBN 052
opportunities
1.1 | Reserves and resources reporting – PRMS
Since 2009, EBN has used the SPE Petroleum Resour- ces Management System (PRMS) for reporting reser- ves and resources. The PRMS classifies hydrocarbon reserves and resources according to the level of certainty of technically and economically recoverable volumes and their potential to reach commercial status. EBN has a very diverse portfolio of conventional and unconventional assets, currently comprising 870 projects. PRMS makes it possible to track and monitor these assets so as to achieve auditable and consistent reporting standards.
| General overview of historical
1.2 | production in the Netherlands
The E&P industry has been a major pillar of the Dutch economy for the past 50 years, during which time approximately 3600 billion cubic metres (BCM) of gas
have been produced from Dutch fields. The Netherlands is still the largest natural gas producer and exporter in the European Union. The lion’s share of this production came from the Groningen field, the ninth largest gas field in the world. In 2013, the Groningen gas field produced approximately 54 BCM.
In order to ensure sustainable production, the Dutch government decided in the early 1970s to introduce the
‘small fields policy‘. This policy states that small fields are produced in preference to the Groningen field and has been very successful in stimulating exploration for and exploitation of smaller gas fields. Since the policy’s intro- duction in 1974, about 1500 BCM have been discovered in small onshore and offshore gas fields. In 2013, around 26 BCM Groningen Equivalent (GE) of gas were produ- ced from some three hundred small gas fields in which EBN participates.
The Petroleum Resources Management System (PRMS)
EBN 2014
Discovered Commercial Production Resource
cat.
Volumes BCM (GE,
unrisked)
Reserves
On production 1 124
Approved for development 2 22
Justified for development 3 20
Sub- commercial Contingent
Resources
Development pending 4 17
Development unclarified or on hold 5 114
Development not viable 6 70
Unrecoverable
Undiscovered
Prospective Resources
Prospect 8
> 200
Lead 9
Play 10
Unrecoverable
N.B.= Cat. 8 and 9 are risked with Probability of Success (POS)
In 2009, EBN formulated its 30/30 ambition for gas pro- duction from small fields in an effort to minimise the de- cline in production from these fields. Thanks to increased activities, this decline, which primarily affects offshore fields, has stabilised at only 2.5% in the past two years.
Applying end of field life (EOFL) techniques, a process known as mature field optimisation, may increase production by several BCMs. EOFL treatments have so far been applied to over 200 wells and EBN expects another 250 wells to be treated in the next five years.
‘Foam injection’ and ‘velocity string’ techniques generate the largest increase in production. Although the costs of EOFL techniques are still high, they are expected to fall significantly as these techniques become more widely used. Cooperation between industry partners in, for example, the Top consortium for Knowledge and Inno- vations (TKI) and Joint Industry (JIP) projects is essential for the further development of EOFL techniques. These techniques, based on innovative ideas that give rise to
Gas Production in 2013
EBN 2014
80 BCM Total gas production
54 BCM Groningen gas production (528 x 103 GWh) 26 BCM Small field gas production (254 x 103 GWh)
2003 - 2013 Dutch gas production, including Groningen
EBN 2014
Groningen Field Onshore Fields Offshore Fields
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
90
75
60
45
30
15
0
BCM (GE)
new technologies, have proven to be highly rewarding, with increases in ultimate recovery of 10% or more being achieved.
| Reserve and resource
1.3 | database
The reserves base of the small fields (i.e. all fields with the exception of Groningen) has decreased from 234 to 166 BCM GE since 31 December 2007 (PRMS catego- ries 1, 2 and 3).
After an initial increase in 2008-2009, followed by a sharp decline between 2009 and 2011, the decrease in reserves has levelled off in recent years. The reductions in offshore and onshore reserves are attributable to pro- duction. However, an increase in ultimate recovery has contributed to a slight reduction in decline rate of offsho- re and onshore reserves. This is the result of a combi- nation of three factors: maturing contingent resources into reserves, definition of new projects with reserves,
and updating the ultimate recovery estimates for existing projects. Although the relative importance of these three factors varies from year to year, maturing existing resources and approval of new projects are the most important. Maturation includes the transfer of contingent resources to reserves, re-evaluation of reserve volumes, and re-evaluation and transfer of certain volumes of prospective resources to reserves.
The ratio of offshore reserves to total reserves decreased slightly from 68% to 63% over the six years from 2007 to 2013, while the ratio of offshore production to total production fell from 75% to 71%. Significant maturation of offshore resources into reserves will consequently be required to maintain the offshore fields’ share in total production and reserves. This in turn will require consi- derable investments.
The average maturation into reserves for the 2007-2013 period was 18.6 BCM GE per year, with 13.3 BCM of
Small fields reserves after production and added reserves
EBN 2014
Offshore reserves after production Onshore reserves after production
Offshore added reserves Onshore added reserves
2007 2008 2009 2010 2011 2012 2013
250 225 200 175 150 125 100 75 50 25 0
Small fields reserves [BCM GE]
this being contributed by offshore resources. Annual maturation into reserves is still significant: the Dutch E&P industry’s continual investments in exploration and development projects have resulted in an average reser- ves replacement ratio of over 60%. The 2013 reserves replacement ratio was even in excess of 75%. Although the reserves replacement ratio for offshore fields has im- proved in the past two years, it is still well below 100%.
1.4 | Gas production forecast
Over the past two years, the Dutch E&P sector has seen a small decline (2.5%) in annual gas production from small fields (see section 1.2). Production from the licen-
in 2013 than in 2012, while the amount of produced con- densate even increased. The small fields reserves base (PRMS categories 1, 2 and 3) fell by only 6.3 BCM.
Despite these relatively positive signs, the long-term outlook has changed considerably compared to that published in the 2013 edition of Focus on Dutch Oil and Gas. In the past few years, replenishment of reserves has relied mainly on gas being transferred from the con- tingent resources categories (PRMS 4, 5 and 6) to the reserves categories (PRMS 1, 2 and 3). Thanks to new technologies and favourable gas prices, Dutch operators have been able to identify increasing opportunities within existing fields and discoveries. Many operators have recently announced plans to start developing long-stran-
Cumulative maturation into reserves for 2007-2013
EBN 2014
Offshore Onshore
2007 2008 2009 2010 2011 2012 2013
120
100
80
60
40
20
0
(BCM GE)
Increased number of activities have stabilized production decline from small fields
300
small fields
fields to even higher levels. There are signs, however, that the underlying growth needed in the contingent resources categories is flattening out, while the numbers of exploration wells and exploration successes in the Dutch E&P sector were both lower in 2013 than requi- red to slow down, let alone halt, the annual decline in production.
Assuming the operators’ exploration efforts in recent years to be representative for future exploration activity levels, the annual future gas production in a ‘business as usual’ (BAU) scenario will fall faster than previously forecast. In previous editions of Focus on Dutch Oil and Gas, EBN assumed that operators holding the most prospective acreages would increase their exploration
efforts. If this does not materialise, EBN expects a lower contribution to the forecast from yet to be discovered fields. EBN will therefore continue encouraging operators to aggressively explore their own acreages, while also being committed to encouraging exploration beyond established play boundaries, and promoting a favourable Dutch E&P climate.
The latest BAU forecast represents a scenario in which the project portfolio permits maintaining a plateau pro- duction level of 28 BCM for the next five years. After that, the decline will resume, unless investments are made in onshore and offshore exploration to unlock further tradi- tional and also more challenging resources, such as tight gas and shale plays. The ‘upside’ scenario relies heavily
Scenario-based risked production forecast small fields gas production
EBN 2014
Produced and in production (cat 1) Produced and in production (no EBN)
Approved or justified for development (cat 2 & 3) Development pending (cat 4)
Development unclarified (cat 5) Development currently not viable (cat 6)
Prospective resources (cat 8 & 9) High case contingent resources (cat 5) High case contingent resources (cat 6) Tight gas development (cat 9) Shale gas development (cat 9) Increased exploration effort (cat 9 & 10)
1990 1995 2000 2005 2010 2015 2020 2025 2030 2035 2040
60
50
40
30
20
10
0
BCM/Y
Upside Business as usual
on these latter resources. It is vital to mature these plays if the Netherlands wants to avoid a rapid decline in gas production within the next decade. However, 2013 saw no major breakthroughs in the development of tight gas fields, while political and societal opposition has pushed potential shale gas development even further back in time. EBN nevertheless expects both shale and tight gas to become increasingly important in the coming two decades.
1.5 | Benefits of Dutch natural gas
EBN seeks to maximise domestic production of na- tural gas in a safe and sustainable manner because it contributes to State revenues, employment and energy self-sufficiency, as well as to a sustainable energy supply by minimising greenhouse gas (GHG) emissions.
In discussions about the role of natural gas in the transition towards a more sustainable energy system
some parties have claimed that relying on natural gas will frustrate this transition as it is a fossil fuel and thus inherently a cause of GHG emissions. Others claim, however, that natural gas is the ultimate transition, or even destination, fuel as it is the cleanest fossil fuel, with ample global reserves. One argument in favour of natural gas is that it will be needed as a fall-back or base-load energy source because of the intermittent nature of solar and wind energy.
Natural gas is beyond doubt the backbone of the Dutch energy system, and Dutch natural gas seems likely to remain important for the foreseeable future, even if the transition to a fully sustainable energy supply is achieva- ble.
According to the ‘business as usual’ scenario, the Netherlands will be able to remain self-sufficient for at least another decade. In the ‘upside’ scenario, howe- ver, we could still produce about half of the country’s
Dutch natural gas consumption and production scenarios
EBN 2014
Gas production – BAU scenario (including Groningen) Natural gas consumption (ECN baseline 2013)
Small fields natural gas – Upside scenario
2015 2020 2025 2030 2035 2040
80
70
60
50
40
30
20
10
0
BCM
NL net exporter
NL net importer
Historical natural gas revenues to Dutch State
EBN 2014 16
14
12
10
8
6
4
2
0
Natural gas revenues (€bln) Share of natural gas revenues in total State revenues (%)
1966 1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
20
15
10
5
0
Natural gas revenues (€ bln) Share of natural gas revenues in total State revenues (%)
Greenhouse gas footprint: domestic versus imported gas
EBN 2014
Conventional natural gas
(domestic production) Shale gas
(domestic production) Liquefied natural gas
(Algeria) Conventional natural gas (Russia) 200
180 160 140 120 100 80 60 40 20 0 GHG emissions (g CO2-equiv. / kWh)
Comparison of up- and mid-stream greenhouse gas emissions of different natural gas supply sources for consumption in the Netherlands.
(Source: Royal Haskoning DHV, 2013)
forecast consumption in 2040. Besides self-sufficiency, there are other important reasons for seeking to maxi- mise domestic gas production in a safe and sustainable manner. Revenues from natural gas production are very important to the Dutch State; over the past twenty years, natural gas revenues have on average accounted for 5 to 10% of total State revenues. The gas sector is also important for domestic employment as it is currently directly responsible for some 6,000 highly skilled jobs and indirectly for another 10,000 jobs at supplier and contractor companies.
Another, albeit less well-known aspect is that the GHG footprint of domestic natural gas is considerably smaller than that of imported natural gas.
In 2013, the independent international engineering consultants Royal HaskoningDHV worked with Utrecht University on a life-cycle analysis (LCA) of up- and mid- stream GHG emissions from various energy options. This study compared GHG emissions on a life-cycle basis
for various options for supplying natural gas consu- med in the Netherlands and also compared these with other energy sources such as coal, nuclear, solar and wind. The study shows that up- and mid-stream GHG emissions from domestic conventional production and domestic production from shale gas amount to 22g CO2-equiv/ kWh, which is far less than the GHG footprint of imported gas such as Algerian liquefied natural gas (LNG), which is transported by ship, or gas from Russia, which has to travel 6000 kilometres through a pipeline.
LNG’s larger footprint is due to the fact that the process of production, liquefaction, shipping and regasification is relatively energy-intensive. Import of Russian gas requi- res compression and inherently leads to small amounts of methane gas leakage as well. As methane gas causes 25 times more global warming than CO2, imported Russian gas has the highest GHG footprint of the options investigated (177 grams of CO2-equiv/ kWh).
In addition, domestic natural gas is more attractive than imported gas from both a security-of-supply and a balance-of-payments perspective.
Margins of small field production
EBN 2014
2009 2010 2011 2012 2013
30
25
20
15
10
5
0 Price (€ cent/m3, Real Term 2013)
- Finding costs: mainly geology & geophysics (G&G) costs (including seismic surveys and expen- sed dry exploration wells);
- Depreciation: on a unit-of-production (UOP) basis (depreciation over successful exploration wells, that are activated, is included in this category);
- Production costs: including transport, treatment, current and non-current costs;
- Taxes: Including Corporate Income Tax (CIT) and the State Profit Share (SPS)
Net profit Taxes Depreciation Finding costs Production costs
| Profit margins on production
| from small fields remain
1.6 | attractive
An attractive and stable Dutch E&P investment climate is crucial in order to support investments. As explained ear- lier, production potential is still significant, and the foreca- sted long-term demand is also sufficient. A breakdown of the revenues from the production from small fields shows that the actual profit margins on gas production remain attractive. The year 2013 showed a rise in average gas prices for the fourth consecutive year. This resulted in a higher profit margin for the E&P industry (‘net profit’) and increased tax revenues for the Dutch State (‘taxes’) per m3.
The long term trend of increasing production costs for each m3 of produced gas has not continued in 2013.
Constraining production costs is especially important for the continued production of tail-end resources and to extend the lifespan of offshore infrastructure (see section 3.4).
| Marginal fields and
1.7 | prospects incentive
A stable and attractive fiscal climate is necessary to con- tinue and increase exploration and production activity. In 2010 the Dutch Ministry of Economic Affairs introduced a specific investment tax allowance, the ‘Marginal Fields Tax Allowance’ (MFTA), to make investments in marginal offshore gas fields more attractive. This allowance targets the development of those gas fields and prospects on which returns are expected to be economically marginal as a result of limited volumes, low field productivity, long distances to existing infrastructure or a combination of these aspects. If a field/prospect qualifies as marginal the operator (and its partners in the license) can deduct an additional 25% of the Investments from the financial
Sizes of marginal fields (recoverable volumes)
EBN 2014
33%
8% 5%
54%
< 1 BCM 1-2 BCM
2-3 BCM
> 3 BCM Marginal Fields Tax Allowance applications
Distance to infrastructure (km)
EBN 2014
16%
8%
11%
8% 8%
49%
0-5 km 5-10 km
10-15 km 15-20 km
20-25 km
> 25 km Marginal Fields Tax Allowance applications
Expected productivity (mln m3/day)
EBN 2014 30%
6% 5%
35%
24%
0-0.5 mln m3/day 0.5-1.0 mln m3/day
1.0-1.5 mln m3/day 1.5-2.0 mln m3/day
2.0-2.5 mln m3/day
Marginal Fields Tax Allowance applications
result calculated for SPS purposes (State Profit Share).
Since the MFTA’s introduction in 2010, 35 applications for the allowance, including some for exploration wells, have been made. Of these, 24 have been granted, and these resulted in 12 field developments being
implemented by the end of 2013. Given the total of 23 offshore field developments in the Netherlands between 2010 and 2013, this demonstrates the importance and success of tax incentives for encouraging specific field developments.
Marginal fields tax allowance
EBN 2014
2011 2012 2013 2014
14
12
10
8
6
4
2
0
Number of applications
Under evaluation Rejected Granted
Decision year
Historical investment level in small gas fields
EBN 2014
onshore investments offshore investments
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
1400
1200
1000
800
600
400
200
0
€ mln 100% RT 2013
Two MFTA applications have been rejected, while the remainder are still under consideration. More than half the applications relate to small prospects or fields expected to yield less than 1 BCM. Over one third of the applications concern prospects or fields at distances of over 10 km from existing infrastructure, while nearly 60%
have low to medium productivity.
| Historical and required
1.8 | investment levels
Although individual operators’ investments in the explora- tion for and production of gas fields vary significantly from year to year, overall investments in small gas fields have remained fairly stable since 2005. Long-term annual investment levels have been around €1.0 to €1.2 billion.
In this context, investments include G&G, and explorati- on costs and capex.
It should be noted that total E&P investment levels in 2013 dropped below €1.0 billion, because some invest-
Investment level scenarios
EBN 2014
Historical investment level BAU FODOG 2013 Upside FODOG 2013
1400
1200
1000
800
600
400
200
0
€ mln 100% RT 2013 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
EBN will continue to encourage and assist operators to
maximize investment level
ments were postponed from 2013 to 2014, and also because some investment budgets were transferred from E&P to gas storage projects. However, as the level of investments planned by operators in 2014 looks very promising, the drop in 2013 may prove to be a one-off event. The investment portfolio is dominated by offshore projects.
A limiting factor for offshore investment can be the number of drilling rigs available for the Dutch offshore sector. In order to keep investments at the required level, Dutch operators need to have adequate access to drilling rigs. Failing this, mature well proposals face unnecessary delays which may lead to missed deadlines on well commitments and cause delays down the activity stream. EBN uses its overview of all Dutch E&P activities
tunities in order to optimise availability and utilisation of available rigs and to ensure that no rig remains idle.
The 2013 edition of ‘Focus on Dutch Oil & Gas’ pre- sented three scenarios for future production levels and, therefore, investment levels: ‘no further activity’ (NFA),‘- business as usual’ (BAU) and the ‘upside’ scenario, as illustrated in the above diagram. The desired future pro- duction levels clearly require a sharp rise in investment over the coming years. Annual investment levels should rise significantly towards the upside scenario, especially if we are seeking to increase exploration activities and subsequently develop tight gas fields and shale plays.
Most of the future investments are required in order to mature offshore resources into reserves. The above
Breakdown offshore investment ambition
EBN 2014
Historical investment level offshore Upside exploration offshore Upside non exploration offshore
BAU exploration offshore BAU non exploration offshore
1400
1200
1000
800
600
400
200
0
€ mln 100% RT 2013 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
required, with ‘non-exploration’ defined as investments required for maturing existing discoveries into reserves on production. Aggressive exploration and appraisal will be needed for maturing prospective resources, including tight gas, into reserves. These investments are labelled as ‘exploration’ in the diagram on page 17.
EBN is firmly in favour of stimulating offshore exploration in particular because the recent exploration efforts of the industry have caused us to lower the BAU exploration scenario as further stipulated in section 1.4.
A timely focus on investments in offshore exploration is also required because the lifespan of the offshore infrastructure depends on ensuring continued sufficient natural gas production. If key infrastructure is decommis- sioned, the related exploration potential will also be lost.
In addition to exploration activities in licensed acreages, exploration in open acreages will also be needed to achieve the upside scenario. EBN encourages this by promoting seismic acquisition and sharing data and opportunities identified in in-house studies, as well as by drawing existing and new operators’ attention to open acreage.
| Comparison of reinvestment
| levels: Netherlands versus
1.9 | the rest of the world
In order to assess the current level of E&P investments in the Netherlands, we calculated the percentage of the cash flow from operations that is reinvested in the Dutch E&P sector (‘reinvestment level’). Generic assumptions were made for all licence holders in order to estimate operational cash flows. Rather, therefore, than exact
Reinvestment level of Dutch small fields compared to Global range
EBN 2014 2000 1800 1600 1400 1200 1000 800 600 400 200 0
€ mln 100% RT 2013 Reinvestment level
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0
Investment level NL Reinvestment level (right axis) Global range reinvestment level
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
NL range reinvestment level
Global range reinvestment level
figures, the figures presented here are rough estimates of the reinvestment level.
Only a third of the cash flow generated in the Nether- lands from Dutch E&P activities is reinvested in new Dutch E&P activities, while the remainder is invested elsewhere in the world or paid out as dividend. The worldwide reinvestment ratio for major E&P operating companies in the past two years was some two to three times higher. The reinvestment level in the Netherlands is consequently lagging seriously behind the global level.
EBN realises that major E&P companies’ investments budgets are currently under pressure and that E&P investments are subject to a global ranking process.
Investments in high-capital and high-risk projects are coming under particularly close scrutiny by shareholders demanding dividends. On the other hand, this might be an opportunity for a mature basin like the Netherlands offering relatively low capital and low risk projects.
Although EBN’s ambition of 30 BCM/year from small gas fields in 2030 and its related investment ambition are challenging, we believe that sufficiently attractive invest- ment opportunities exist and are actively pursuing further improvements in the investment climate. In conclusion:
Maximizing economic recovery by means of safe and sustainable domestic gas production, will benefit both the E&P industry and the Dutch society as a whole.
in the Dutch E&P industry
| Increasing drilling activity in 2.1 | the Netherlands
E&P activities in 2014 are expected to be at a higher level than in 2013. EBN classifies oil and gas activities in the Netherlands into six types of projects: field develop- ment, wells drilled, enhanced gas recovery, pipelines, storage and abandonment/decommissioning. The num- ber of planned exploration, appraisal and development wells in 2014 is markedly higher than the number of wells drilled in 2013: the total of 36 wells (18 exploration and appraisal wells and 18 production wells) planned for 2014, which is 10 more than in 2013, may herald the start of a much-awaited increase in E&P activity and investments.
| Historical E&P activity 2.2 | levels in the Netherlands
A total of 49 operators have been active in the Nether- lands since 1946, when commercial hydrocarbon pro- duction in the country started. Between 1937 and 1967, the only operator was NAM (and its predecessor, the Bataafsche Petroleum Maatschappij). In the aftermath of the chaotic exploration situation in 1963, the number and variety of operators increased from 1967 until the early 1990s. This was followed by a significant decrease, which was at least partly due to the low oil prices at the time. Since 2005, however, the number of operators has started increasing again.
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12
10
8
6
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Number of operators active based on drilling activity Number of wells drilled
1963 1964 1965 1966 1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 120
100
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Number of operators based
on drilling activity Number of wells drilling including Schoonebeek, excluding gas storages (right axis)
Number of operators active in the Netherlands, based on drilling activity
Activities 2013
•
Enhanced gas production•
Field development•
Gas storage•
Seismic surveys•
Well drilled•
Abandoned wellEBN 2014
Activity: Seismic reprocessing symposium
In February 2014, EBN and GDF SUEZ organised a one-day symposium on ‘Seismic Processing in the Netherlands’, at which ten less well-known geophysical companies presented their seismic processing capabilities to representatives of the Dutch petroleum and geothermal industries. Most of these presentations can be found on our website (www.ebn.nl).
The idea behind this symposium was that nume- rous 3D surveys have been acquired in the Netherlands to date, while many legacy surveys have now been processed or reprocessed. Most of the reprocessing has been done by three to four large companies, with smaller and relatively unknown companies often being overlooked in the tendering process. By organising this symposium, EBN gave the geophysical contractors a forum to display their capabilities.
Some 70 people from 23 companies active in the Netherlands attended the symposium, with ten geophysical contractors presenting interesting material. The symposium was very well received by contractors and audience alike, and EBN is examining the opportunities for
a follow-up in 2014.
| Innovative solutions to increase
| oil and gas recovery in the
| Netherlands – TKI innovation 2.3 | projects
In 2012 the Dutch government initiated a policy to en- courage innovation, for which nine specific sectors were identified. Dutch academia and industry are seen as having considerable knowledge and experience in these
‘Top Sectors’, which are seen as the most promising tar- gets for successful innovation and international competi- tiveness. Of particular interest for the oil and gas industry are the ‘energy’ and ‘water’ sectors.
EBN participates in TKI Gas (Top consortium for Knowledge and Innovations), which focuses mainly on upstream gas innovations (www.upstream-gas.nl). The objective of this programme is to develop innovative solutions to help maximise the recovery of gas from the Dutch subsurface, particularly from small fields. The ‘up- stream gas’ innovation programme is structured along three lines: Tough Gas, Mature Fields and New Fields.
Several operators active in the Netherlands participate in one or more projects in these programme lines. TNO and the technical universities (Utrecht, Delft and Eindhoven) perform most of the ‘upstream gas’ projects. Several of these projects are described in this year’s edition of Focus on Dutch Oil and Gas.
Tough Gas
Although potentially huge resources of tough gas – such as shale and tight gas – are present in the subsurface of
Innovative solutions to increase recovery from the small gas fields
10%
Increase
recovery
Upstream gas – innovation projects
EBN 2014
Tough Gas Mature Fields
Upstream Gas TKI Gas
Energy Top Sectors
New Fields
– High resolution characterisation of fine- grained sedimentary rock
– Clay swelling – Posidonia sweet spot – Innovative water management
– Water production and treatment – Integrated compression solutions – Salt precipitation
– Experimental foam influence evaluation – Realtime monitoring and optimization – Enhanced gas recovery
– New petroleum systems in the Dutch northern offshore
– JUSTRAT: Tectonostratigraphic frame- work for the upper Jurassic – lower Cretaceous
– Integrated pressure information system for the onshore and offshore Netherlands.
the Netherlands, new technologies are needed to impro- ve the economic viability of such Tough Gas projects.
Mature Fields
In mature fields, the reservoir pressure has decreased to levels where compression is required to produce the gas.
Projects in the Mature Fields line focus on technological developments seeking to extend the life of these fields.
Relevant research themes fall into the Production & Reser- voir Management and the Infrastructure categories.
New Fields
Successful exploration is key to increasing investment levels and production of both gas and oil. Even though the Netherlands is a mature area, new fields are conti- nually being found and developed. And while exploration in a mature province poses special challenges, such as the proximity and multiple use of subsurface resources, it also provides opportunities, given the high-density data and infrastructure cover.
Innovation project: De-risking shale plays and understanding source rock, Posidonia Sweet Spot JIP study
When examining shale reservoirs in outcrop, the first impression may often be that the rocks look very homogeneous and, therefore, that it should be relatively straightforward to predict their reservoir characteristics. This impression is based on the overall fine-grained nature, great lateral continuity and overall constant thickness and dark colour. If, however, we have a closer look, it soon becomes clear that nothing could be further from the truth.
Gas and oil shales consist of a complex mixture of clay- and silt-sized particles and have a highly vari- able organic material content, and it is this organic material that is vital for generating hydrocarbons.
In productive shale accumulations elsewhere, this heterogeneity translates into highly variable well productivity.
The most important exploration target for shale gas and oil in the Netherlands, the Jurassic Posidonia Formation, lies at a considerable depth. These rocks are known only from borehole measure- ments and, in the Netherlands, cannot be studied at outcrop. For this reason, EBN is participating in the Posidonia Sweet Spot study, a Joint Industry Project (JIP) aimed at a better understanding of the geological make-up and production characteristics of time-equivalent marine shales exposed along the UK East Coast. Initial results show many similarities with the Dutch subsurface, but have also highligh- ted many of the small-scale complexities seen in shale provinces around the world. Future results of this work are expected to help us to predict high-productivity intervals more accurately and thus help reduce the development footprint commonly associated with shale developments elsewhere.
| Hydraulic stimulation is key to
| achieving economic production from 2.4 | poor-quality reservoirs
In the past decade, hydraulic stimulation has become a key technique for achieving economic production from otherwise uneconomic reservoirs. Hydraulic stimulation has been used to enhance hydrocarbon production in the US since the late 1940s, and in the Netherlands since the 1950s. Over the past decade, a combination of horizontal drilling and extended, multi-stage hydraulic sti- mulation has unlocked the unconventional hydrocarbon potential in the United States. This ‘fracking’ improves well economics and enables more prolific oil and gas production from zones once considered non-commer- cial. In the past two decades, gas production from US shale gas reservoirs has risen dramatically from 1% to over 50% of total US gas production and is continuing
Hydraulic Stimulation in the US shale play
Recovery Factor vs. number of stages
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OGIP recovery factor Number of stages
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Number of Stages USA Recovery Factor Source: G. King, SPE 152596
1980’s 1990’s 2001 2004 2006 2008 2010 2011 Future
to increase every year. However, it should be noted that the terminologies for shale gas and conventional gas are completely different. The ‘recovery factor’ in shale gas reservoirs is defined as the fraction of oil/gas recovered
from the volume within the anticipated well drainage area, which is largely defined by the well spacing. Con- versely, the ‘recovery factor’ in conventional reservoirs is defined as the fraction of oil/gas recovered from the
Average recovery factors in conventional fields vs. tight fields in the Netherlands
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gas fields Single stage hydraulic
stimulation tight fields Multi stage hydraulic stimulation tight fields 100%
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Recovery factor
Hydraulically stimulated wells with number of stages applied in the Netherlands
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Hydraulically stimulated wells
1 stage 2 stages 3 stages 4 stages 5 stages
entire field, and this is not directly related to well spacing.
Of the existing gas fields in the Netherlands, 85% are producible by conventional technology. The average recovery factor from these conventional fields is generally around 80% or higher. The remainder of the EBN portfo- lio is categorised as tight fields, where recovery factors are considerably lower than in conventional fields.
Single-stage hydraulic stimulation (in tight reservoirs) shows an average recovery factor of 47%. In order to increase recovery from these fields, operators have been using multi-stage hydraulic stimulation and horizontal drilling. Although not many multi-stage stimulation ope- rations have been performed in the Netherlands to date,
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Injected Propant (kg)
20.00 - Max 10.00 - 20.00 Min - 10.00 Empty
Shape indicates production success
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Average concentration fracture (kg/m2)
Injected proppant vs. average concentration fracture
Color indicates average maximum concentration fraction
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Injected proppant vs. fluid pumped with different proppant sizes
Color indicates proppant size
the average recovery factor is 56%. In different upside scenarios, it is possible to reach a 60% recovery factor for these tight fields.
EBN has performed a multivariate statistical analysis on the results of 93 hydraulic stimulation treatments in the 70 wells that were stimulated in the Netherlands between 1995 and 2012. Our analysis took account of the impact of reservoir properties such as formation type and per- meability; proppant size and proppant volume pumped;
fluid volume; and frac length, height and width. Roughly one in ten wells drilled between 1995 and 2012 was hydraulically stimulated.
EBN collected data for 83 of the 93 hydraulic stimula- tions. Of these 83 stimulations, 71 were considered a success, meaning that all the proppant was placed as planned and the clean-up of the well was performed without any major operational difficulties. A total of 53 of the stimulations were considered a production success, which is defined as a satisfactory post-frac production rate. A stimulation is considered a production success if the post-frac rate is:
1 | at least twice the pre-frac rate,
2 | comparable to the modelled post-frac rate, or 3 | much better than the rate of an unfracked well in the
same field.
Whether the stimulations are also an economic success depends mostly on the duration of the improved well performance.
The likelihood of a hydraulic stimulation treatment being successful increases per frac stage from an average of 55% to over 90% when the pumped proppant volume exceeds 100 tons per frac and/or the average concen- tration exceeds 10 kg/m2. The success rate also increa- ses with the grain size of the pumped proppant.
EBN 2014
3D seismic coverage of the Netherlands, time slice at 1 second TWT.
Image - K5-B Monotower
innovations of offshore infrastructure
| Offshore infrastructure, a brief 3.1 | history and innovation over time
Exploration drilling on the Dutch continental shelf started in 1962 and picked up later that decade, resulting in the first offshore gas development in license L10/L11a. The first platform on the Dutch continental shelf was part of the Placid (now GDF SUEZ) L10-A central complex, which was built in 1974 and where production commen- ced in 1975.
In the Dutch offshore, with water depths in the range of 20 to 40 metres, platforms traditionally consist of top-side modules supported by a braced jacket. The first facilities typically consisted of a central processing platform, connected to wellhead platforms (or satellites)
and to an accommodation platform. New developments in the vicinity typically used satellite platforms connected via an inter-field pipeline to the central processing (or host) platform.
L10-A central complex (courtesy of GDF SUEZ E&P Nederland B.V.)
Installations installed by year
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Number of installations
subsea monotower satelite processing
1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Installations in operation (cumulative)
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Installations in operation
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1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Over time, field size decreased and cheaper facility concepts (such as subsea wellheads, tripods and mono- towers) had to be designed. Placid was the first party to opt, in 1988, for a facility with subsea wellheads at L10-S1. Subsea wells were tied back to the central host complex by pipelines, similar to traditional satellites. Ano- ther lower-cost type of concept, the ‘tripod’, sometimes referred to as the ‘bird box’, was first used by Unocal (now Chevron) in 1986 for the Q1-Helder-B oil develop- ment and in 1995 also by Elf Petroland (now Total) for the K5-B gas field development. Both platforms have tripod substructures: the platform consists of a tripod below sea level, with a monotower on top.
NAM installed its first (steel) monotower in the K17-FA
field in 2005 and placed two more monotowers on K5-B monotower with tripod substructure (courtesy of Total E&P Nederland B.V.)
installed a monotower based on the same design at M7-A in 2009. Whereas satellite platforms used to be equipped with independent power generation by either gas turbines or diesel engines, the K17-FA, L9-FA/FB and M7-A monotowers were equipped with renewable energy systems (windmills and solar panels).
In order to reduce operating costs for fields with a declining production, as well as enable the economic development of smaller accumulations, the traditional manning levels of satellite platforms had to be reduced over time. As the continuing innovation in communication technology permits remote operation of satellite plat- forms, these are now normally unmanned.
3.2 | Innovations in offshore E&P
Suction anchors
Suction anchors were first applied in 1996-1997 by Clyde (now Wintershall) at three satellite platforms in
the P2 and P6 blocks. These satellites are now all being re-used for other Wintershall field developments (P2-SE for P6-D in 2000, P2-NE for Q4-B in 2002 and P6-S for Q1-D in 2013). Other applications of suction anchors are at F3-FA installed by Centrica in 2010, at a Riser Access Tower adjacent to NAM’s K15-FA platform in 2011, at GDF SUEZ’s Q13-A Amstel in 2013 and at Wintershall’s L6-B minimum facility monotower/tripod, which is to be installed in 2014.
Eductors
Various operators have recently acquired new seismic data within their mature production licences and are developing smaller accumulations, either with smaller and lower-cost installations or by extended-reach drilling from existing satellites. When high-pressure gas beco- mes available at existing installations, this energy can be used to enhance the recovery of low-pressure mature fields by applying eductors (i.e. jet pumps; for a detailed
L9- FB-1 monotower (courtesy of NAM B.V.)
Q13-A Amstel satellite (courtesy of GDF SUEZ E&P Nederland B.V.) uses suction piles
description, see the 2013 edition of Focus on Dutch Oil and Gas).
“Walk-to-Work” systems
Satellites were traditionally designed to be self-sufficient and equipped with helicopter decks, cranes and gas or diesel-driven power generation. In 2008, offshore access systems were introduced that, under most conditions, allow marine access to platforms, thus avoiding the need for a helicopter deck and costly helicopter movements.
The same technique of compensating vessel motion to provide a stable walkway is also being applied to allow cranes to work off a supply vessel; future installations may, therefore, have smaller or no cranes.
Innovations: Walk-to-work systems
‘Walk-to-work’ systems are a relatively new concept and generally consist of a dynamically stabilised access system mounted on a support vessel. The position of the system relative to the
platform is maintained by using fast-acting hydraulics to continuously adjust for wave move- ment, a technology similar to that used in flight simulators. These systems ensure a safe and comfortable transfer of staff from the support vessel to the platform structure, a step change compared with the traditional boat-to-structure transfer methods. The same technology may soon be used for position-compensated cranes and other machinery, thereby increasing the versatility of these vessels and bringing them into direct competition with jack-up systems.
Re-use of platforms
Although re-use of platforms is common in the Gulf of Mexico, re-use within the Dutch E&P sector is typically restricted to the same affiliate. To date 11 satellite plat- forms (normally only the topsides) have been re-used in new field developments. The main advantage of re-use is not so much saving costs, but rather shortening the lead time needed for constructing new facilities and, therefo- re, accelerating first production, while at the same time reducing the environmental footprint.
3.3 | Tail-end production and optimisation
As the first offshore gas production started some 40 years ago, it is not surprising that many fields have now reached the final phase of production. Because of the maturity of the area, cost-effective tail-end production is
Offshore access system (courtesy of Ampelmann Operations B.V.)
